Closed previously announced divestments of certain properties in the Permian Basin, Green River Basin, and Mississippi for an aggregate selling price of approximately $59.9 million, subject to customary post-closing adjustments in the second quarter of 2018

Closed three additional divestitures subsequent to June 30, 2018 for aggregate gross proceeds of $28.4 million, including its Potato Hills assets in Oklahoma which closed for gross proceeds of $22.9 million and interests in over 145 wells in multiple counties in Texas and Louisiana for gross proceeds of $5.5 million

Amended the Company’s revolving credit facility to provide additional flexibility and successfully completed its first borrowing base redetermination since emerging from restructuring in 2017

Reported production volumes of 363 million cubic feet equivalent (MMcfe) per day, near the mid-point of second quarter guidance

Lease operating expenses were $36.8 million, at the mid-point of second quarter guidance

Selling, general and administrative expenses (excluding non-cash compensation and severance) were 12% lower than first quarter 2018

Participated in two new Arkoma Woodford horizontal wells that had an average 30 day IP of 8.8 MMcf per day per well

Updated third quarter and full-year 2018 operational and financial guidance for the year, with an updated 2018 capital budget of approximately $130.0 million to $140.0 million

Remain significantly hedged for the balance of 2018 and through 2020 with the balance of 2018 production hedged 76%, 90% and 43% for natural gas, oil and NGLs, respectively, at the mid-point of announced guidance

Added Rockies basis hedges for the periods of August 2018 to October 2018 and November 2018 to March 2019 for approximately 60% and 40% of our Rockies natural gas production, respectively

Added Midland–Cushing basis hedges for 2019 for a portion of our Permian production

Mr. R. Scott Sloan, President and CEO, commented, “This year has been about transitioning Vanguard from an upstream MLP to a successful exploration and production company focused on organic growth. The key first step in that journey is divesting non-core assets, and I am pleased with our continuing progress in this area. The end result will be a more focused portfolio and a strengthened balance sheet. Additionally, we continue to make operational and organizational changes to align the Company with this strategy and to set the Company up for future success.”

Second Quarter 2018 Highlights

Reported average production of 363 MMcfe per day in the second quarter of 2018 represents a 1% decrease compared to 368 MMcfe per day for the first quarter of 2018 and was at the mid-point of guidance when normalizing for divestitures closing sooner than initially expected. The production decrease from the first quarter was primarily attributable to the planned shutdown of the BEC facility in Alabama and the closing of the Permian and Mississippi asset divestitures at the beginning of June 2018. On a Mcfe basis, crude oil, natural gas, and NGLs accounted for 14%, 71% and 15%, respectively, of our second quarter 2018 production.

Lease operating expenses (“LOE”) of $36.8 million during the second quarter of 2018 ($1.11 per Mcfe) increased 18.7% compared to the $31.0 million in the first quarter of 2018 ($0.94 per Mcfe) and was at the mid-point of guidance. The increase is primarily due to the planned shutdown of the BEC facility and the associated maintenance in Alabama and other seasonal expense items across the portfolio.

Transportation and gathering expenses related to certain of our natural gas and NGLs contracts were $9.8 million during the second quarter of 2018 ($0.30 per Mcfe) and are lower as compared to $11.5 million in the first quarter of 2018 ($0.35 per Mcfe).

Selling, general and administrative expenses (“SG&A”) were $11.1 million during the second quarter of 2018 ($0.34 per Mcfe). Excluding non-cash compensation of $0.6 million and severance costs of approximately $1.8 million, SG&A was $8.7 million for the second quarter of 2018, a decrease of 12% compared to the $9.9 million reported in the first quarter of 2018 ($0.38 per Mcfe) and at the low end of guidance. The first quarter of 2018 excludes $0.5 million of non-cash compensation and $2.3 million in severance costs.

Depreciation, depletion and amortization expenses (“DD&A”) were $38.7 million in the second quarter of 2018 ($1.17 per Mcfe), representing a decrease of 3% from $40.0 million in the first quarter of 2018 ($1.21 per Mcfe). The reported DD&A decreased primarily due to lower impairment charges and the sale of properties in the Permian Basin in the second quarter of 2018, both of which reduced our depletable base for the current period.

We reported a net loss attributable to Common Stockholders for the second quarter of 2018 of $57.8 million. This compares to a net loss attributable to Common Stockholders of $32.7 million in the first quarter of 2018. The increase in the Company’s reported net loss for the second quarter of 2018 is primarily attributable to lower revenues due to lower realized natural gas prices combined with increased losses on commodity derivative contracts (realized and unrealized). This was partially offset by lower impairment expense and a realized gain on divestitures in the second quarter.

Adjusted Net Loss Attributable to Common Stockholders (a non-GAAP financial measure defined below) was $25.2 million in the second quarter of 2018. This compares to Adjusted Net Loss of $4.7 million in the first quarter of 2018. The Adjusted Net Loss for the second quarter of 2018 included adjustments for net non-cash expenses of $30.1 million primarily comprised of a $7.6 million impairment charge on our oil and natural gas properties and a $27.5 million loss from the change in fair value of commodity derivative contracts, offset by a $4.9 million net gain on asset sales. The Adjusted Net Loss for the first quarter of 2018 results included adjustments for net non-cash expenses of $23.9 million primarily comprised of a $14.6 million impairment charge on our oil and natural gas properties and a $9.3 million loss from the change in fair value of commodity derivative contracts.

Adjusted EBITDA (a non-GAAP financial measure defined below) was $30.5 million in the second quarter of 2018 and represents a 41% decrease as compared to the first quarter of 2018. The decrease as compared to the first quarter of 2018 is attributable primarily to a decrease in natural gas revenues due to lower realized pricing, as well as greater realized losses on our commodity derivative contracts.

Capital expenditures for the second quarter of 2018 were $38.4 million, down from $42.1 million in the first quarter of 2018. This $3.7 million decrease from the first quarter is primarily attributable to lower capital spend in the Piceance Basin, which was partially offset by higher spend in the Pinedale field. Drilling and development in the Pinedale field, located in the Green River Basin, and the Mamm Creek field in the Piceance Basin, accounted for approximately 84% of the Company’s total capital costs for the period. In Pinedale, we participated as a non-operated partner in the drilling and completion of 12 horizontal and 18 vertical natural gas wells. In Mamm Creek, we completed six wells and we are currently in the process of completing the last three wells of the 2018 development drilling program. In the Arkoma Basin, we participated as a non-operated partner in the drilling and completion of two horizontal Woodford wells.

2018 Six Month Highlights:

Reported average production of 365 MMcfe per day in the first six months of 2018 represents a 4% decrease compared to 381 MMcfe per day during the same period in 2017. The production decrease was primarily attributable to divestitures completed during 2017 and 2018. On a Mcfe basis, crude oil, natural gas, and NGLs accounted for 15%, 71% and 14%, respectively, of our year to date June 30, 2018 production.

LOE of $67.8 million during the first six months of 2018 ($1.02 per Mcfe) decreased 10% compared to the $75.3 million during the first half of 2017 ($1.09 per Mcfe).

Transportation and gathering expenses related to certain of our natural gas and NGLs contracts were $21.3 million during the first half of 2018 ($0.32 per Mcfe).

SG&A were $23.8 million during the first six months of 2018 ($0.36 per Mcfe). Excluding non-cash compensation of $1.1 million and severance costs of approximately $4.1 million, SG&A was $18.6 million for the first six months of 2018, an increase of 24% compared to $15.0 million reported during the first six months of 2017 ($0.29 per Mcfe). The 2017 SG&A also excludes non-cash compensation of approximately $5.1 million.

DD&A were $78.8 million during the first half of 2018 ($1.19 per Mcfe), representing an increase of 54% from $51.1 million ($0.74 per Mcfe) during the same period in 2017. The reported DD&A increased primarily due a higher amortization base as a result of the application of fresh-start accounting, which led to a corresponding increase in the depletion rate per equivalent unit of production for the period.

We reported a net loss attributable to Common Stockholders during the first six months of 2018 of $90.5 million. This compares to a net loss attributable to Common Unitholders of $65.0 million during the comparable period in 2017. The increase in the Company’s reported net loss for the first six months of 2018 is primarily attributable to impairment expenses reported during the period.

Adjusted Net Loss Attributable to Common Stockholders (a non-GAAP financial measure defined below) was $29.9 million during the first six months of 2018. This compares to Adjusted Net Income of $27.7 million in the first six months of 2017. The Adjusted Net Loss during the first six months of 2018 included adjustments for net non-cash expenses of $54.0 million primarily comprised of a $22.2 million impairment charge on our oil and natural gas properties and a $36.8 million loss from the change in fair value of commodity derivative contracts, offset by a $4.9 million net gain on asset sales. The Adjusted Net Loss for the same period in 2017 included adjustments for net non-cash expenses of $12.8 million primarily comprised of a loss from the change in fair value of commodity derivative contracts.

Adjusted EBITDA (a non-GAAP financial measure defined below) was $82.4 million for the first six months of 2018 and represents a 29% decrease as compared to the same period in 2017. The decrease as compared to the first six months of 2017 is attributable primarily to an increase in SG&A and decreased production.

Capital expenditures for the first six months of 2018 were $80.5 million, up from $37.3 million during the comparable period in 2017. Drilling and development in the Pinedale field, located in the Green River Basin, and the Mamm Creek field in the Piceance Basin, accounted for approximately 85% of the Company’s total capital costs for the period. In Pinedale, we participated as a non-operated partner in the drilling and completion of 14 horizontal and 65 vertical natural gas wells, and in Mamm Creek, we have drilled and completed 11 wells in our 14 well program. Year to date in the Arkoma basin, we participated in the drilling and completion of seven horizontal Woodford wells.

Selected Financial Information

A summary of selected financial information follows (in thousands, except for production data):

Successor

Predecessor

Three Months

Three Months

Three Months

Ended

Ended

Ended

June 30, 2018

March 31, 2018

June 30, 2017

Production (Mcfe/day)

363,088

367,568

377,822

Oil, natural gas and natural gas liquids sales

$

111,713

$

123,275

$

106,867

Net losses on commodity derivative contracts

$

(45,332)

$

(18,585)

$

(12,875)

Operating expenses (1)

$

44,734

$

40,776

$

45,961

Selling, general and administrative expenses

$

11,108

$

12,736

$

9,777

Net Loss Attributable to Vanguard Common Stockholders/

Unitholders

$

(57,773)

$

(32,684)

$

(53,867)

Adjusted Net Income (Loss) Attributable to Vanguard
Common Stockholders/Unitholders (2)

$

(25,181)

$

(4,679)

$

12,229

Adjusted EBITDA attributable to Vanguard Common

Stockholders/Unitholders (2)

$

30,467

$

51,981

$

53,288

Total Debt (as of June 30, 2018 and 2017, and March 31, 2018, respectively)

Non-GAAP financial measures. Please see Adjusted Net Income Attributable to Common Stockholders/Unitholders and Adjusted EBITDA attributable to Vanguard Stockholders/Unitholders tables at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure.

Average Prices and Production Volumes

Three Months
Ended
June 30,

Percentage

Increase /(Decrease)

Three Months
Ended

March 31,

Percentage

Increase /(Decrease)

2018 (a)

2017 (b)

2018 (a)(b)

Average realized prices, excluding hedges:

Oil (Price/Bbl)

$

59.32

$

42.52

40

%

$

55.30

7

%

Natural Gas (Price/Mcf)

$

1.81

$

2.21

(18)

%

$

2.36

(23)

%

NGLs (Price/Bbl)

$

28.45

$

16.19

76

%

$

27.91

2

%

Average realized prices, including hedges (c):

Oil (Price/Bbl)

$

40.65

$

42.52

(4)

%

$

41.66

(2)

%

Natural Gas (Price/Mcf)

$

1.88

$

2.21

(15)

%

$

2.63

(29)

%

NGLs (Price/Bbl)

$

22.18

$

16.19

37

%

$

22.78

(3)

%

Average NYMEX prices:

Oil (Price/Bbl)

$

67.89

$

48.31

41

%

$

62.89

8

%

Natural Gas (Price/Mcf)

$

2.80

$

3.18

(12)

%

$

2.98

(6)

%

Total production volumes:

Oil (MBbls)

784

965

(19)

%

834

(6)

%

Natural Gas (MMcf)

23,573

23,362

1

%

23,371

1

%

NGLs (MBbls)

794

871

(9)

%

785

1

%

Combined (MMcfe)

33,041

34,382

(4)

%

33,081

—

%

Average daily production volumes:

Oil (Bbls/day)

8,615

10,608

(19)

%

9,266

(7)

%

Natural Gas (Mcf/day)

259,049

256,729

1

%

259,674

—

%

NGLs (Bbls/day)

8,725

9,575

(9)

%

8,717

—

%

Combined (Mcfe/day)

363,088

377,822

(4)

%

367,568

(1)

%

(a)

In accordance with the adoption of ASC Topic 606, the average realized natural gas and NGLs prices for the three months ended June 30, 2018 and the three months ended March 31, 2018 exclude gathering, transportation, and processing fees of $9.8 million and $11.5 million, respectively, related to certain of our natural gas and NGLs marketing and processing agreements that were reclassified and presented as Transportation, gathering, processing, and compression expense in our condensed consolidated statements of operations. As such, our average realized prices are not comparable with the prior periods. If our natural gas and NGLs revenues are shown net of these fees, the average realized natural gas price and average NGLs price excluding hedges would be $1.49 and $25.52, respectively, for the three months ended June 30, 2018, and $2.00 per Mcf and $24.13 per Bbl, respectively, for the three months ended March 31, 2018.

(b)

During 2018 and 2017, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.

(c)

Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.

Six Months Ended June 30,

Percentage

Increase /(Decrease)

2018 (a)(b)

2017 (b)

Average realized prices, excluding hedges:

Oil (Price/Bbl)

$

57.24

$

43.78

31

%

Natural Gas (Price/Mcf)

$

2.09

$

2.32

(10)

%

NGLs (Price/Bbl)

$

28.18

$

18.00

57

%

Average realized prices, including hedges (c):

Oil (Price/Bbl)

$

41.17

$

43.79

(6)

%

Natural Gas (Price/Mcf)

$

2.25

$

2.32

(3)

%

NGLs (Price/Bbl)

$

22.48

$

18.00

25

%

Average NYMEX prices:

Oil (Price/Bbl)

$

65.31

$

50.11

30

%

Natural Gas (Price/Mcf)

$

2.89

$

3.24

(11)

%

Total production volumes:

Oil (MBbls)

1,618

1,957

(17)

%

Natural Gas (MMcf)

46,944

47,022

—

%

NGLs (MBbls)

1,578

1,710

(8)

%

Combined (MMcfe)

66,122

69,020

(4)

%

Average daily production volumes:

Oil (Bbls/day)

8,939

10,811

(17)

%

Natural Gas (Mcf/day)

259,359

259,788

—

%

NGLs (Bbls/day)

8,721

9,445

(8)

%

Combined (Mcfe/day)

365,315

381,327

(4)

%

(a)

In accordance with the adoption of ASC Topic 606, the average realized natural gas and NGLs prices for the six months ended June 30, 2018 exclude gathering, transportation, and processing fees of $21.3 million related to certain of our natural gas and NGLs marketing and processing agreements that were reclassified and presented as Transportation, gathering, processing, and compression expense in our condensed consolidated statements of operations. As such, our average realized prices are not comparable with the prior periods. If our natural gas and NGLs revenues are shown net of these fees, the average realized natural gas price and average NGLs price excluding hedges would be $1.74 and $24.83, respectively, for the six months ended June 30, 2018.

(b)

During 2018 and 2017, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.

(c)

Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.

Asset Divestiture Update

During 2018, we completed the sale of certain oil and natural gas properties in the Permian basin, the Green River basin and in Mississippi for an aggregate selling price of approximately $59.9 million, subject to customary post-closing adjustments. Additionally, we incurred costs to sell of approximately $1.3 million. Since June 30, 2018, we have closed three additional divestitures for aggregate proceeds of $28.4 million, including our Potato Hills assets in the Arkoma Basin for gross proceeds of $22.9 million and interests in over 145 wells in multiple counties in Texas and Louisiana for gross proceeds of $5.5 million. Proceeds from the sales were used to reduce borrowings under our revolving credit facility.

Additionally, we are evaluating bids after publicly marketing our Arkoma basin properties in Arkansas, which comprise all of our interests located within the state. The properties include operated and non-operated working interests, with current production of approximately 8 MMcfe per day, and associated development rights. The Company has also begun marketing on EnergyNet its ownership in five operated producing wells and related undeveloped acreage in the DJ Basin in Weld County.

We continue to progress other non-core asset sale processes and are actively preparing additional assets for divestment, including certain assets in the Midcontinent and the Gulf Coast areas. The sales of these properties are anticipated to further reduce debt under the Company’s revolving credit facility and sharpen the focus of the portfolio.

Operational Update

The Company continues to invest in key assets and evaluate future potential in new resources, primarily in the Pinedale field of the Green River Basin, the Piceance Basin, and the Arkoma Woodford.

In the Pinedale field, production remained flat at approximately 117 MMcfe per day in the second quarter of 2018 from approximately 117 MMcfe per day in the first quarter of 2018. As one of our operators reduces drilling activity in the field, we anticipate third quarter production to remain at current levels, with an overall modest decline for the full year. As noted in the operator’s earnings release, they are slowing horizontal drilling to one rig and increasing vertical well drilling in the near term. We are supportive of this change in pace to learn from recent horizontal results and optimize the program going forward. Additionally, we are comfortable that the currently planned vertical wells represent a high-graded group of wells that should deliver solid economic returns even in today’s gas price environment.

In the second quarter of 2018, the Arkoma Woodford area produced approximately 31 MMcfe per day. Vanguard participated in the drilling and completion of two wells operated by BP America, Inc. (“BP”). Both wells have come in above our curve type expectations with an average 30 day IP of 8.8 MMcf per day. In the second half of 2018, the Company will participate in seven additional wells which Newfield Exploration Company (“Newfield”) will operate. Production from these seven wells is expected in the first quarter of 2019.

The Piceance assets produced approximately 73 MMcfe per day for the second quarter of 2018, up approximately 3% from the first quarter. We have drilled 14 vertical gas wells and we have just completed the final three wells of this 14 well program with a modified completion design. The drilling and completion program has been completed ahead of schedule and on budget and all the wells were completed successfully as designed. Preliminary production results have been less than the initial uplifted type curves we anticipated for the first 11 wells. The focus in the balance of the year will be to analyze the data from the 14 well program and evaluate how to best proceed in future development of the large resource still in place.

Capital Expenditures Update

Total capital expenditures were approximately $80.5 million during the six months ended June 30, 2018. We currently anticipate a total capital expenditures budget ranging from $130.0 million to $140.0 million for the full year of 2018, down from our May 2018 guidance. This decrease is primarily due to a modest delay in Newfield’s Arkoma Woodford drilling program, where we are participating in seven wells as a non-operated partner.

In the Green River Basin, we are on track to spend between $20.0 million and $25.0 million in the Pinedale Field for the remainder of 2018, where we will participate in the drilling of vertical and horizontal natural gas wells with partners Ultra Petroleum Corporation and Pinedale Energy Partners. In the Arkoma Basin we are on track to spend approximately $15.0 million of our remaining 2018 capital budget where we will be participating as a non-operated partner with Newfield Exploration Company in a one rig program, drilling and completing horizontal Woodford wells. We have a large drilling inventory in the Arkoma basin where we will continue to advance our understanding and evaluation of the potential for an operated program in late 2019 or early 2020. In the Piceance Basin, our operated drilling and completion program is continuing as planned at the Mamm Creek Field where we expect to spend an additional $6.0 million during the remainder of 2018. The balance of our remaining drilling and completion capital will be spent on additional drilling, completion and production uplift projects in the Permian and Big Horn Basins.

Revised 2018 Guidance

New guidance is being issued for the third quarter and full year of 2018 to reflect the updated investment allocation and to incorporate the operational and financial results of the first half of 2018. Production is now estimated to be in the range of 343 MMcfe per day to 355 MMcfe per day and 348 MMcfe per day to 362 MMcfe per day for the third quarter and full year of 2018, respectively.

“Overall, our revised 2018 guidance considers more than $28.0 million in additional divestments with production of approximately 6 million cubic feet equivalent per day closing in August and a decrease in capital spend for the balance of the year. Because the horizontal Pinedale results have been variable to date, we are forecasting a slower pace of drilling and lower level of participation in that program. Although we are forecasting less production growth from Pinedale, this impact to cash flow has partially been mitigated by the recent improvement in Rockies basis pricing, for which we have added hedges in the near-term to lock in” commented Mr. Midgett.

The following table sets forth the Company’s revised guidance for 2018 which is based on certain estimates being used by the Company to model its anticipated results of operations for the 2018 fiscal year. These estimates include the recently closed divestment of the Company’s Potato Hills properties.

Q3 2018E

FY 2018E

Net Production:

Oil (Bbls/day)

7,700

–

8,200

8,200

–

8,650

Natural gas (Mcf/day)

247,000

–

253,000

249,000

–

257,000

NGLs (Bbls/day)

8,300

–

8,800

8,300

–

8,850

Combined (Mcfe/day)

343,000

–

355,000

348,000

–

362,000

Costs ($ in thousands):

Lease operating expenses

$

28,000

–

$

33,000

$

125,000

–

$

133,000

Production taxes (% of revenue)

9

%

–

10

%

8

%

–

9

%

G&A expenses(1)

$

9,000

–

$

11,000

$

40,000

–

$

43,500

Interest expense

$

15,500

–

$

16,500

$

60,500

–

$

64,500

Capital expenditures

$

22,500

–

$

27,500

$

130,000

–

$

140,000

Average NYMEX Differentials(2):

Oil ($/Bbl)

$

(10.00)

–

$

(12.00)

$

(8.00)

–

$

(11.00)

Natural gas ($/MMBtu)

$

(1.05)

–

$

(1.25)

$

(1.05)

–

$

(1.20)

NGLs realization of crude oil price (%)(3)

38

%

–

42

%

38

%

–

42

%

(1)

Includes post-emergence restructuring related costs of $3.5 million for the balance of 2018.

(2)

Includes impact of transportation and gathering costs that may be classified as operating expenses under ASC Topic 606. In Q2 2018, transportation and gathering expenses related to certain of our natural gas and NGLs contracts were $9.8 million.

As of August 1, 2018, we have $662.0 million of outstanding borrowings under the reserve-based credit facility and approximately $50.0 million of liquidity after reflecting a $0.2 million reduction in availability for letters of credit and approximately $9.0 million in available cash.

Ryan Midgett, Chief Financial Officer, commented, “With the amended terms to our credit agreement, the Company has additional flexibility to continue its ongoing portfolio optimization efforts and divestment program. We continue to have sufficient liquidity to maintain our business plan and our ongoing divestments are anticipated to further reduce debt and enhance liquidity over the course of the year. I want to again thank our lenders for their continued support of Vanguard. As previously stated, rightsizing the balance sheet continues to be the primary focus for 2018, and our ongoing divestment strategy will help the Company pay down debt, improve liquidity, and position the Company for future success as we invest in our asset base.”

Hedging Activities

The Company has implemented a hedging program for its crude oil and natural gas production through 2021, and NGLs production through 2019. Currently, we use fixed-price swaps, basis swap contracts, and collars to hedge oil, natural gas and NGLs prices. The Company believes its hedging program will provide substantial near-term cash flow visibility regardless of the volatility in commodity prices as management and the board of directors explore options for maximizing stockholder value.

The Company has entered into Rockies natural gas basis hedges for 105,000 MMBtu per day at a weighted average price of ($0.62) per MMBtu for the period of August 2018 to October 2018 (excludes 50,000 MMBtu per day hedged at ($0.69) in July 2018) and 60,000 per MMBtu per day at a weighted average price of ($0.53) per MMBtu for the period of November 2018 to March 2019. This equates to approximately 60% and 40% of the Company’s Rockies natural gas production for the respective periods. Additionally, the Company has entered into Midland–Cushing basis hedges for 1,250 barrels per day at a weighted average price of ($5.78) per barrel for 2019.

For a summary of all commodity derivative contracts in place at June 30, 2018, please refer to our Quarterly Report on Form 10-Q which was filed on August 9, 2018.

Conference Call Information

The Company will host a conference call Monday, August 13, 2018, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss the Company’s second quarter 2018 results. There will be prepared remarks by R. Scott Sloan, President & Chief Executive Officer, and Ryan Midgett, Chief Financial Officer, followed by a question and answer session.

Investors and analysts are invited to participate in the call by dialing 1-323-794-2588, or 888-394-8218 for toll free calls using Conference ID: 5243529. Interested parties may also listen over the internet at www.vnrenergy.com. A replay of the call will be available on the Company’s website.

About Vanguard Natural Resources, Inc.

Vanguard Natural Resources, Inc. is an independent exploration and production company focused on the production and development of oil and natural gas properties in the United States. Vanguard’s assets consist primarily of producing and non-producing oil and natural gas reserves located in the Green River Basin in Wyoming, the Piceance Basin in Colorado, the Permian Basin in West Texas and New Mexico, the Arkoma Basin in Arkansas and Oklahoma, the Gulf Coast Basin in Texas, Louisiana and Alabama, the Big Horn Basin in Wyoming and Montana, the Anadarko Basin in Oklahoma and North Texas, the Wind River Basin in Wyoming and the Powder River Basin in Wyoming. More information on Vanguard can be found at www.vnrenergy.com.

Forward-Looking Statements

Statements made by representatives of the Company within this press release that are not historical facts are forward looking statements. Terminology such as “will,” “would,” “should,” “could,” “expect,” “anticipate,” “plan,” “project,” “intend,” “estimate,” “believe,” “target,” “continue,” “on track,” “potential,” the negative of such terms or other comparable terminology are intended to identify forward looking statements. These statements are based on certain assumptions and expectations made by the Company which reflect management’s experience, estimates and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or anticipated in the forward looking statements. These include risks relating to financial performance and results, the ability to improve Vanguard’s results and profitability following its emergence from bankruptcy; our indebtedness under our revolving credit facility, term loan and second lien notes; availability of sufficient cash flow to make payments on our debt obligations and to execute our business plan; our prices and demand for oil, natural gas and natural gas liquids; and our ability to replace reserves and efficiently develop our reserves. These and other important factors could cause actual results to differ materially from those anticipated or implied in the forward looking statements. Please read “Risk Factors” in our most recent annual report on Form 10-K and Item 1A. of Part II “Risk Factors” in our subsequent quarterly reports on Form 10-Q and any other public filings and press releases. Vanguard undertakes no obligation to publicly update any forward looking statements, whether as a result of new information or future events.

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income (loss) attributable to Vanguard stockholders/unitholders in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) attributable to Vanguard stockholders/unitholders plus:

Net income (loss) attributable to non-controlling interest.

The result is net income (loss) which includes the non-controlling interest. From this we add or subtract the following:

Non-controlling interest amounts attributable to each of the items above which revert the calculation back to an amount attributable to the Vanguard stockholders/unitholders.

Adjusted EBITDA is used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry.

Adjusted EBITDA is not intended to represent cash flows for the period, nor is it presented as a substitute for net income (loss), operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

VANGUARD NATURAL RESOURCES, INC.

Reconciliation of Net Loss to Adjusted EBITDA

(Unaudited)

(in thousands)

Successor

Predecessor

Three Months

Three Months

Three Months

Ended

Ended

Ended

June 30, 2018

March 31, 2018

June 30, 2017

Net loss attributable to Vanguard stockholders/unitholders

$

(57,773)

$

(32,684)

$

(53,867)

Add: Net income (loss) attributable to non-controlling interests

96

93

(5)

Net loss

$

(57,677)

$

(32,591)

$

(53,872)

Plus:

Interest expense

15,870

14,753

13,832

Depreciation, depletion, amortization, and accretion

38,711

40,039

25,328

Impairment of oil and natural gas properties

7,552

14,601

—

Exploration expense

430

1,316

—

Change in fair value of commodity derivative contracts (a)

27,485

9,293

12,875

Net gain on divestiture of oil and natural gas properties

(4,900)

—

—

Taxes

—

—

(436)

Compensation related items

579

496

2,456

Reorganization items

610

1,707

53,221

Severance costs

1,845

2,256

—

Material costs incurred on strategic transactions

—

148

—

Adjusted EBITDA before non-controlling interest

30,505

52,018

53,404

Adjusted EBITDA attributable to non-controlling interest

(38)

(37)

(116)

Adjusted EBITDA attributable to Vanguard stockholders/
unitholders

$

30,467

$

51,981

$

53,288

(a)

These items are included in the net losses on commodity derivative contracts line item in the consolidated statements of operations as follows:

Net gains on interest rate derivative contracts as shown on the consolidated statements of operations is comprised of the following:

Predecessor

Six Months

Ended

June 30, 2017

Cash settlements paid on interest rate derivative contracts

$

(95)

Change in fair value of interest rate derivative contracts

125

Net gains on interest rate derivative contracts

$

30

Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders

We present Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders in addition to our reported net income (loss) attributable to Common Stockholders/Unitholders in accordance with GAAP. Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders is a non-GAAP financial measure that is defined as net income attributable to Common Stockholders/Unitholders plus the following adjustments:

Change in fair value of commodity derivative contracts;

Change in fair value of interest rate derivative contracts;

Net gains on divestiture of oil and natural gas properties;

Impairment of oil and natural gas properties;

Reorganization items;

Severance costs; and

Material costs incurred on strategic transactions.

We present Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders because management believes exclusion of the impact of these items will help investors compare results between periods and identify operating trends that could otherwise be masked by these items and to highlight the significant fluctuations that commodity price volatility has on our results, particularly as it relates to changes in the fair value of our derivative contracts.

In particular, we make the adjustment for the change in fair value of commodity derivative contracts to allow investors to make a comparison of our quarterly results without the non-cash impact of commodity price fluctuations from period to period resulting from changes in the mark-to-market value of our portfolio of commodity derivative contracts. Rather than highlighting the significant fluctuations that commodity price volatility has on Net Income (Loss), we are aiming to give investors a meaningful picture of our performance (especially versus prior periods) that shows how the Company performed without the impact of the value of our portfolio of commodity derivative contracts. The fluctuations in the value of our portfolio of commodity derivatives contracts is related to futures pricing which is not a good indicator of historical performance of the business during the periods presented. Furthermore, any increases or decreases in the value of our portfolio of commodity derivatives contracts will result in non-cash charges or non-cash income. The inherent value (or cost) of such contracts is the amount of cash which our counterparties pay to us, or, with respect to costs, the amount which we paid to acquire the contracts and the amount that we are required to pay to our counterparties upon settlement. We believe this non-GAAP measure allows our investors to measure our actual performance without the impact of certain non-cash items that do not actually reflect the performance of the Company for the periods presented.

We also make the adjustment for the change in fair value of interest rate derivative contracts to give investors a period to period comparison without showing the impact of non-cash gains or losses related to the mark-to-market valuation of these derivatives contracts.

Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

VANGUARD NATURAL RESOURCES, INC.

Reconciliation of Net Loss Attributable to Common Stockholders/Unitholders to

Adjusted Net Income (Loss) Attributable to Common Stockholders/Unitholders

(in thousands, except per share/unit data)

(Unaudited)

Successor

Successor

Predecessor

Three Months

Three Months

Three Months

Ended

Ended

Ended

June 30, 2018

March 31, 2018

June 30, 2017

Net Loss Attributable to Vanguard Common
Stockholders/Unitholders

$

(57,773)

$

(32,684)

$

(53,867)

Plus (less):

Change in fair value of commodity derivative contracts(a)

27,485

9,293

12,875

Net gains on divestitures of oil and natural gas properties

(4,900)

—

—

Impairment of oil and natural gas properties

7,552

14,601

—

Reorganization items

610

1,707

53,221

Severance costs

1,845

2,256

—

Material costs incurred on strategic transactions

—

148

—

Adjusted Net Income (Loss) Attributable to Vanguard
Common and Class B Stockholders/Unitholders

$

(25,181)

$

(4,679)

$

12,229

Net Loss Attributable to Vanguard Common
Stockholders/Unitholders, per share/unit

$

(2.87)

$

(1.63)

$

(0.41)

Plus (less):

Change in fair value of commodity derivative contracts(a)

1.37

0.46

0.10

Net gains on divestitures of oil and natural gas properties

(0.24)

—

—

Impairment of oil and natural gas properties

0.37

0.73

—

Reorganization items

0.03

0.08

0.40

Severance costs

0.09

0.11

—

Material costs incurred on strategic transactions

—

0.01

—

Adjusted Net Income (Loss) Attributable to Vanguard
Common and Class B Stockholders/Unitholders, per
share/unit

$

(1.25)

$

(0.24)

$

0.09

Weighted average common shares/common and Class B

units outstanding

20,100

20,100

131,381

(a)

Change in fair value of commodity derivative contracts reflects the increase or decrease in the mark-to-market value of the commodity derivative contracts. Any increase in value is reduced from Net Income (Loss) Attributable to Common Stockholders/Unitholders, while any decrease is added back into Net Income (Loss) Attributable to Common Stockholders/Unitholders.

Successor

Predecessor

Six Months

Six Months

Ended

Ended

June 30, 2018

June 30, 2017

Net Loss Attributable to Vanguard Common
Stockholders/Unitholders

$

(90,457)

$

(65,021)

Plus (less):

Change in fair value of commodity derivative contracts(a)

36,778

12,875

Change in fair value of interest rate derivative contracts(b)

—

(125)

Net gain on divestiture of oil and natural gas properties

(4,900)

—

Impairment of oil and natural gas properties

22,153

—

Reorganization items

2,317

79,967

Severance costs

4,101

—

Material costs incurred on strategic transactions

148

—

Adjusted Net Income (Loss) Attributable to Vanguard
Common and Class B Stockholders/Unitholders

$

(29,860)

$

27,696

Net Loss Attributable to Vanguard Common
Stockholders/Unitholders, per share/unit

$

(4.50)

$

(0.49)

Plus (less):

Change in fair value of commodity derivative contracts(a)

1.83

0.09

Change in fair value of interest rate derivative contracts(b)

—

—

Net gain on divestiture of oil and natural gas properties

(0.24)

—

Impairment of oil and natural gas properties

1.10

—

Reorganization items

0.11

0.61

Severance costs

0.20

—

Material costs incurred on strategic transactions

0.01

—

Adjusted Net Income (Loss) Attributable to Vanguard
Common and Class B Stockholders/Unitholders, per
share/unit

$

(1.49)

$

0.21

Weighted average common shares/common and Class B

units outstanding

20,100

131,379

(a)

Change in fair value of commodity derivative contracts reflects the increase or decrease in the mark-to-market value of the commodity derivative contracts. Any increase in value is reduced from Net Income (Loss) Attributable to Common Stockholders/Unitholders, while any decrease is added back into Net Income (Loss) Attributable to Common Stockholders/Unitholders.

(b)

Change in fair value of interest rate derivative contracts reflects the increase or decrease in the mark-to-market value of the interest rate derivative contracts. Any increase in the fair value of interest rate derivative contracts is reduced from Net Income (Loss) Attributable to Common Stockholders/Unitholders, while any decrease in the fair value of interest rate derivative contracts is added back into Net Income (Loss) Attributable to Common Stockholders/Unitholders.